Investors Guide Shale Gas 2007

A S U P P L E M E N T T O

J A N U A R Y 2 0 0 7

AN INVESTOR’S GUIDE TO SHALE GAS

www.oilandgasinvestor.com | January 2007 | 1

SHALE GASIntroduction

1616 S. Voss, Ste. 1000 Houston, Texas 77057Tel: (713) 993-9320Fax: (713) 840-0923

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Editor in ChiefLESLIE HAINES, Oil and Gas Investor

Executive EditorNISSA DARBONNE, Oil and Gas Investor

Director of Custom PublishingMONIQUE A. BARBEE

Senior Exploration EditorPEGGY WILLIAMS, Oil and Gas Investor

Contributing EditorTARYN MAXWELL

Photo EditorLOWELL GEORGIA

Art DirectorALEXA SANDERS

Senior Graphic DesignerLAURA J. WILLIAMS

Production ManagerJO LYNNE POOL

For additional copies of this publication,contact Marcos Alviar at 713-260-6439.

Associate PublisherSHELLEY LAMB

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Corporate Director of MarketingJEFF MILLER

A supplement to

Sr. Vice President and Chief Financial Officer

KEVIN F. HIGGINS

Executive Vice President FREDERICK L. POTTER

President and Chief Executive Officer

RICHARD A. EICHLER

Copyright 2007, Oil and Gas Investor/Hart Energy Publishing LP, Houston, Texas

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About the Cover: Earlier this year, XTO Energy’s Carter B No. 1-H was fractured by Frac Tech near Eagle MountainLake in Tarrant County, Texas. (Photo by Lowell Georgia)

SHALE SIZZLES

ANew York Times article reported last October that in Fort Worth,Texas, along Interstate 30, a billboardadvertises, “If you don’t have a gas well, get one!”

Yes,gas shale plays are now attracting national media attention,not to mention some 64 public E&P com-panies now report some involvement in at least one shale play. Shales are creating a booming business.

More than 100 rigs are running in the Barnett Shale around Fort Worth, with some eye-popping leasebonuses being paid—even right underneath the Dallas-Fort Worth airport and Lake Arlington.The Barnettalone is producing about 2 billion cubic feet per day,making it the largest gas field in Texas and a major con-tributor to U.S. gas production.

A pattern of intense—some would say frantic and stealthy—leasing showed up in the Fort Worth Basin’sBarnett Shale in 2003, spread to the Arkansas Fayetteville Shale in 2004 and 2005, then moved toOklahoma’s Woodford,to a Barnett-Woodford look-alike in Far West Texas,and now,is moving to Alabamaand Appalachia.

The value of developed gas shale assets was dramatically illustrated last spring when Chief Oil & GasLLC of Dallas went for $2.15 billion to Barnett Shale leader Devon Energy Corp. The latter estimates atleast 800 more drilling locations from this deal.

The good news continues. In November, EOG Resources pleased investors by raising its net Fort WorthBasin Barnett resource potential by nearly 45%, which could double the amount it has booked for all ofNorth America. A big reason is the company’s “southern extension” area south of the so-called core, espe-cially in Hill County.EOG estimates its net potential there is at least another 1 trillion cubic feet equivalent.

Also last fall, Newfield Exploration and Southwestern Energy reported surging production, higherreserves per well and increased drilling in their Woodford Shale and Fayetteville Shale plays, respectively.

With results like these, no wonder investors want to know more about all the shale plays throughout theU.S. Greater understanding is invaluable. This special

report will provide information about all theseplays, whether they are established ones

rapidly growing or emerging onesattracting new drilling. You’ll get

an update on all the playersinvolved, and you’ll learn moreabout the special technologiesinvolved, as well as the decision-

making hierarchy required.

—Leslie Haines, Editor-in-Chief

CONTENTSTHE SHALE SHAKER With gas at $6 per MMbtu, operators can’t, and won’t, stop pursu-ing shale-gas plays. The number of companies involved is growing.

BIGGER IN THE BARNETT According to this consultant, production in the BarnettShale in the Fort Worth Basin is greater than earlier reports indicated.

FAYETTEVILLE MATURING A recent study shows how different the geology and petro-physics of the Fayetteville and Moorefield shales are from the Barnett Shale.

THE FLOYD/NEIL SHALE In the Black Warrior Basin of Alabama and Mississippi,operators are trying to develop the potential of a new shale play.

UNDERSTANDING THE BARNETT SHALE Now that nearly 6,000 wellshave been drilled, the industry has better knowledge of what makes the Barnett Shale tick.

DECISION-MAKING FOR UNCONVENTIONAL RESOURCESUnderstanding value and risk leads to better decisions, but in unconventional plays, the process must behandled differently.

FIRST-MOVER ADVANTAGE When it comes to shale M&A, it’s usually the first-movers that hold all the cards.

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By John White and Roger Read, Natexis Bleichroeder Inc.

The past 12 months have seen several exciting developmentsin U.S. shale plays. As more E&P companies get involved,

shale-gas production continues to climb and frac techniques con-tinue to advance.

The list of companies pursuing shales continues to grow. Ourfirst report on shales in November 2005 showed 23 publiclytraded companies involved in shale-gas plays. In June 2006, wetallied 39. We now find 64 publicly traded entities. We are cer-tainly missing some because of the sheer magnitude of activityand the fact that companies sometimes hold leases in third-partynames to maintain secrecy (Table 1).

Newfield Exploration Co. appears to have cracked the code onthe Woodford Shale in Oklahoma, as evidenced by significantlyhigher initial flow rates on a string of well completions in late 2006.

The core area of the leading shale, the Barnett Shale aroundFort Worth, still takes first place in terms of rates of return, withTier 1 Barnett and the Woodford now in a virtual tie for secondplace. The Fayetteville Shale in Arkansas is running a close thirdwith Southwestern Energy Co. the most active driller there.

Meanwhile, the emerging Barnett-Woodford play in Far WestTexas appears to have turned in mixed results to date. So far, somewells in this area have been difficult to drill and complete. Oneindustry source said one recent well (unnamed) reportedly camein with a completed well cost of $16 million.

Gas Shale EconomicsOur updated economic model reflects the changes in reserve, pro-duction and cost profiles for the most advanced shale plays: theBarnett, Fayetteville and Woodford.

We expect natural gas prices to average about $7 per MMBtuin 2007. The major shale plays show robust economics at a lower

price, $6 per MMBtu (Figure 1). Given the weakness experiencedin U.S. natural gas prices during third-quarter 2006, we looked atthe economics of these plays under lower gas price assumptions.We ran our downside cases at $4.50 per MMBtu.

Under our expectations of gas prices for 2007, we believe thatrig dayrates have peaked.

The variability within each play and between operatorsdeserves mention. Wells in the core area of the Barnett Shale canrange between 2.5 billion cubic feet equivalent (Bcfe) to 5 Bcfe ofreserves. We are using 3.5 Bcfe for the Barnett core, 2.2 Bcfe forwells in the Tier 1 areas and 1.0 Bcfe for the non-core areas ofthis play.There are also definitional differences in how each com-pany divides up the areas of the play. Some companies use theterms Core 1 and Core 2, while others use Core and Tier 1.

In a sustained gas price environment of about $4.50 perMMBtu, operators would more strictly prioritize drillingprospects assuming current rig rates and oilfield service costs.

Under our analysis, the core area of the Barnett Shale will remaina high priority for drilling. The Barnett area referred to as Tier 1would likely experience a slowdown in activity, though at a 20%average rate of return, selected individual well locations would con-tinue to be drilled, in our opinion.The western and southern edgesof the play, the so-called non-core areas, would likely see a dramaticdrop in drilling activity as returns become negative.

Woodford ShaleThis play, situated in the Arkoma Basin in southeasternOklahoma, is starting to come on strong. Recent results point toa complete step-change in the reserve and production expecta-tions. The industry has been pursuing gas-shale production heresince early 2003. Companies active in the Woodford include thepioneer of the play, Newfield Exploration Co., as well asChesapeake Energy, Devon Energy, XTO, Petrohawk EnergyCorp. and St. Mary Land & Exploration.

As with all of these shale plays, there is the initialdrilling and completion effort, followed by several roundsof using different drilling and completion techniques,together with better subsurface imaging. Each play isunique in terms of best drilling and completion practices.

Newfield appears to have learned much about theWoodford, given its series of recent well completionsthere. Initial flow rates are significantly in excess of pre-viously completed wells. Recent horizontal drillingresults have been strong compared with wells completedearlier in 2006. The recent success is partly because ofincreased fracture densities, such as more frac stages perwellbore.

The new wells show significantly higher initial peakproduction rates and subsequent post-peak productionrates (Table 2).

In addition to improving the design of its fracs,

SHALE GAS Shale Overview

2 | January 2007 | www.oilandgasinvestor.com

Figure 1. Gas Shale Economics Summary. Source: Company reports, NatexisBleichroeder Inc. estimates. Note: Most values vary locally within each play.

THE SHALE SHAKERWith gas at $6 per MMbtu, operators can’t, and won’t, stop pursuing shale-gas plays. The numberof companies involved is growing.



Table 1. A sampling of public companies report activity in a number of shale plays.

Abraxas ABP 64 • •American Oil & Gas AEZ NA •Anadarko Petroleum APC NA • • •Apache APA NA •Bill Barrett BBG NA •Brigham Exploration BEXP 130 • • •Cabot Oil and Gas COG NA • •Carrizo Oil and Gas CRZO 309 • • • • •Chesapeake CHK 1,665 • • • • • • •Chevron CVX NA •Clayton Williams CWEI NA •ConocoPhillips COP 500 • •Contango Oil and Gas MCF 48 •Denbury Resources DNR 50 • •Devon Energy DVN 1,132 • • •Dominion E&P D NA •Edge Petroleum EPEX 38 • •El Paso EP NA •EnCana ECA 745 • • • •Encore EAC 27 • •Energen Corporation EGN 100 •EOG Resources EOG NA • • • • •Equitable Resources EQT NA •Exploration Company TXCO NAExxonMobil XOM NA • •Forest Oil FST 65 • •Infinity IFNY 60 •Marathon Oil MRO NA • •Murphy Oil MUR NA •Newfield Exploration NFX 115 •Noble Energy NBL 175 • • •Parallel Petroleum PLLL 61 •Penn Virginia PVA 85 • • •Petrohawk Energy HAWK 23 • •Petroquest PQ 25 •Pioneer Natural Res. PXD NA •Pogo Producing PPP 168 • • •Questar STR NA •Quicksilver KWK 575 • • •Range Resources RRC 350 • • •Shell RDS-B NA • •Southwestern SWN 1,361 • • •St. Mary Land SM 114 • •Storm Cat SCU 13 •Talisman TLM NA •Williams Co WMB 94 • •XTO Energy XTO 435 • • • •

Altai Resources ATI.V NAAscent Resources plc ACTPF NA •Crimson Exploration CXPO NA •Dune Energy Inc DNE 3.7 •Hallador Petroleum HPCO NA •Ignis Petroleum IGPG 6.9 •Lexington Resources LXRS 5.0 •Morgan Creek Energy MCRE 0.1 •Nitro Petroleum Inc NPTR 7.0 •Nova Energy NVNG NA •Petrosearch Energy PTSG 4.2 •Pilgrim Petroleum PGPM NA •Questerre Energy QEC NATBX Resources TBXC 2.8 •Unicorp Inc UCPI 7.6 •US Energy Holdings USEH NA •Westside Energy WHT 17.2 •Notes: The Bakken is an oil producing shale. Source: Company reports.

Large, Mid and Estimated Shale PlaysSmall-Cap Net Acreage in

Gas Shale Plays Devonian/ Barnett/Company Ticker (thousands) Barnett Fayetteville Woodford Ohio Woodford Floyd New Albany Mowry Gothic Bakken Baxter

Estimated Shale PlaysNet Acreage in

Micro-cap Gas Shale Plays Caney/ Devonian/ Barnett/Companies Ticker (thousands) Barnett Fayetteville Woodford Ohio Woodford Floyd New Albany Mowry Gothic Bakken Baxter


SHALE GASShale Overview

Newfield has highlighted the differences in the rock itself. One ofthe important characteristics is the mineralogy, specifically the sil-ica content. The silica content adds aspects of porosity closer to asandstone or chert, compared with most other shales (Figure 2).The Woodford delivered good economics prior to the release of theresults from recent wells completed in November 2006 (Table 3).

Assuming a gas price of $6 per MMBtu, the after-tax return is61%, but if using a gas price of $4.50 per MMBtu, the returnsdrop to about 13%. The latter is probably a low enough level thatcompanies would decrease drilling in the play and focus only onhigh-graded prospects.

Should the completions reported in November 2006 prove to bethe new “type well” or average for the Woodford play, the econom-ics would dramatically change. We ran the economics again using ahigher production rate of 5 million cubic feet equivalent (MMcfe)per day with the result being a 170% after-tax rate of return.

We would point out another potential advantage the Woodfordhas versus the Barnett is its uphole zones that offer additionalproduction potential.The Caney, Cromwell and Wapanuka zonesall have produced in the region in other fields and wellbores.

Barnett ShaleThis play continues to deliver exceedingly strong results.Production increased by 25% during the first six months of 2006compared with 2005, according to the Texas Railroad Commission.The commission’s preliminary figures, which have tended to beunderstated until more complete reports are submitted, showedproduction of 282 Bcfe during the first six months of 2006, com-pared with 224 Bcfe during the same six months in 2005.

Based on figures supplied by active operators in the play, webelieve current gas production is between 1.8 and 2.1 Bcfe per day.

The field now has about 5,900 producing wells, of which about23% are horizontal completions. Activity continues at a strongpace with about 160 rigs running.

Returns vary between the core area, Tier 1 and the non-corearea, with possible returns ranging from 131% in the core area toonly 32% in the non-core. Well costs are higher in the core, butgross reserves per well are also higher.

As the core area has developed, certain operational issues are arising:

• turnover of the type and vintage of rigs being used;• tightness of supply for pressure pumping equipment

and crews;• water access; and • well permitting and city ordinance issues.Our discussions with operators have indicated that rig rates have

gone flat since May 2006 because of weakness in gas prices andincreased supply of land rigs.The turnover of the type and vintage ofrigs is positive for the Barnett play and other plays.

The land drillers have responded to the tightness in the marketexperienced in 2004 and 2005, bringing new and significantly refur-bished/upgraded equipment to the market. The new upgraded rigsoffer substantial performance improvements.

As older rigs are displaced, they are moving into the Woodford playin eastern Oklahoma and the Fayetteville play in western Arkansas.

Given the size of the Barnett play and the diverse set of operators

and operating practices, the rigs in the play fall into three broad cat-egories based on horsepower. Current rates for these rigs rangebetween $18,000 and $22,000 per day. As the newer rigs move intoservice, we will probably see the lower horsepower and lesser depthcapacity rigs move firmly into the lower end of the range of rates andthe higher capability rigs firmly into the higher end of the range.

The tight supply of pressure pumping equipment comes fromtwo factors. First, the rig count in the play continues to climb andeach well drilled requires a frac job. Second, the supply of waterneeded for these fracs has become scarce. The water access issueis driven by the activity factors mentioned here in addition to thenorthcentral Texas region being affected by a drought for anextended period.

The National Oceanic & Atmospheric Administration hasreported significant rainfall deficits from January 15, 2005, toNovember 15, 2006, throughout northcentral Texas. Rainfall atDallas-Fort Worth International Airport alone was 64% of nor-mal. Water-use restrictions are in effect in Dallas and Fort Worth.

Some permitting and municipal ordinance issues arise as oper-ators seek more access to areas increasingly close to Fort Worthand in other outlying areas that are fully developed for commer-cial and residential use. In general, landowners are drivingtougher deals, demanding higher lease bonus amounts, higherroyalties and stiffer drilling commitments.

From a competitive standpoint, the play is showing characteristicstypical of other areas of E&P activity: larger companies are consoli-dating acreage, reserves and production from smaller companies.Many of the smaller and often privately owned companies have

Figure 2. Comparison of selected gas shales. Source: Companyreports, Ryder Scott, USGS, Natexis Bleichroeder Inc. estimates.

EARLY-STAGE PLAYIn Quebec, Canada, Talisman Energy is chasing the Paleozoic-ageUtica Shale. Talisman drilled an exploration test looking for theTrenton Black River formation in this area. It proved unsuccessful,but there were good gas shows from the Utica. Testing and a comple-tion are being evaluated.

The company will be drilling more of these Trenton Black Riverprospects, also testing this uphole shale on the way to total depth.These will be vertical wells.

Micro-cap E&P companies Questerre Energy and Altai Resourcesare also involved.


completed one or more rounds of initial and subsequent drilling pro-grams. These positions are now attractive to the larger companies,and the smaller companies see this as a good opportunity to mone-tize their investment. (See article on mergers and acquisitions else-where in this report.)

During the first half of 2006, Devon Energy, ChesapeakeEnergy, Range Resources and XTO Energy dominated BarnettShale acquisitions, which have focused on smaller companies or

asset packages of smaller companies.Many in the industry have asked about the future involvement of

the major oil companies in what appears on track to become thelargest onshore gas field in the U.S. ExxonMobil and Shell are involved on a relatively small basis. ConocoPhillips is in the Barnett, but its position is because of its acquisition ofBurlington Resources.

Given their financial strength and technical abilities, the majorsare well suited to plays involving large amounts of capital, complexoperating characteristics and long lead times. These parameters donot describe the Barnett Shale.

However, given the total resource potential of the play, we wouldnot rule out further expansion by the majors, most likely involvingan acquisition. We would envision an acquisition candidate that haslarge Barnett Shale exposure, plus other, meaningful internationaland/or U.S. deepwater Gulf of Mexico exposure. Companies in thiscategory, in our view, are Devon Energy and EOG Resources.

Fayetteville ShaleSince our last update, the most noteworthy data point from this playcontinues to be the slick-water frac completions performance on thehorizontal wells. Southwestern Energy Co., which is the dominantoperator, discovered the play. Previously, the majority ofSouthwestern’s completions involved nitrogen foam fracs, possiblybecause of the low pressure of the reservoir. Since the beginning of

SHALE SHAKERA shale shaker is the primary device on the rig for removing drilledcuttings from the drilling fluid or mud. This vibrating sieve is basi-cally a wire-cloth screen that vibrates while the drilling fluid, togetherwith rock cuttings from the just-drilled formation, flows on top. Theliquid phase of the mud and the portion of the cuttings smaller thanthe wire mesh pass through the screen, while larger pieces of cuttingsare retained on the screen and discarded or saved and bagged as sam-ples for the drilling records. The used fluid is then recycled to godownhole again and bring more cuttings to the surface.

The drilling crew seeks to run the screens as finely as possible,without dumping whole mud off the back of the shaker. Where it wasonce common for drilling rigs to have only one or two shale shakers,modern high-efficiency rigs are often fitted with four or more, givingmore area of wire cloth to use and providing the crew with the flexi-bility to run increasingly fine screens.

Source: Schlumberger Ltd. and Natexis Bleichroeder Inc.



2006, the company ceased nitrogen fracs and began using slick-waterand cross-link gel fracs.

Southwestern reported third-quarter 2006 gross production of70 MMcf per day in the Fayetteville Shale. It expected to increaseproduction to 100 MMcf per day by year-end 2006, a 43%increase in just one quarter.

In mid-November 2006, Southwestern had 14 rigs working inthe play area, up from 10 rigs on July 31, 2006. It planned to have19 rigs running in the Fayetteville Shale by year-end 2006 andrunning through 2007. Southwestern expects to have four morecompany-owned shallow rigs and 15 company-owned deeper rigsby year-end 2007.

Other companies with significant acreage positions in this playare Chesapeake Energy with 340,000 net acres, XTO Energy

with about 220,000 acres, Contango Oil & Gas Co. with 44,000acres, Storm Cat Energy with 13,000 acres, and Carrizo Oil &Gas Inc. with 15,000 acres.

Chesapeake planned to have seven rigs in the region by year-end2006. Carrizo has a 2% working interest in two wells Southwesternoperates. Completions of these two wells were scheduled fromNovember 2006 through February 2007.Carrizo has no plans to drillindividually but assumes it will be pooled into drilling more wellswith Southwestern in 2007.Carrizo is still acquiring acreage in Pope,Van Buren and Conway counties.

Edge Petroleum, with 6,000 net acres in the Fayetteville Shale,took part in several non-operated wells during third-quarter 2006.Additionally, it expected to drill an Edge-operated well inNovember. There are future plans for Edge to drill one or two

Table 2. Recent wells drilled by Newfield Exploration in the Woodford Shale.

Initial Peak Post Peak

Production Flow Rate Wellbore Frac Flow Rate

Commenced Well (MMcfe per day) Design job (MMcfe per day)

MOST RECENTLY ANNOUNCED WELLS:

November 2006 Stuart #1H –13 10.6 2,500’ lateral five-stage

November Tollett #1H-22 10 2,500’ lateral five-stage 6

November Tipton #1H-23 7 3,500’ lateral seven-stage 5

November Turpin #1H-35 7 1,600’ lateral three-stage

November Bullock #1H-15 5 3,500’ lateral five-stage frac 4.1

Mean 7.9 5.0

Median 7 5

PREVIOUSLY ANNOUNCED WELLS:

March 2006 Parker 1H-36 6 NA NA 4.8

March Reeder 1H-10 3 NA NA 2.6

March Whitlow 1H-27 3 NA NA 2.4

Mean 4 3.3

Median 3 2.6

% improvement 98% 54%

133% 92%

Table 3. Economics of Woodford Shale Core Area: $6.00/MMBtu Henry Hub gas price.

Realized State Less Before

Gas Total Production LOE Tax Income Net

Production Price Revenue Taxes (5) and other (6) Income Taxes Income

Year MMcfe ($/MMBtu) ($MM)

1 1059 5.40 5.7 0.09 0.8 4.9 1.7 3.2

2 370 5.40 2.0 0.03 0.3 1.7 0.6 1.1

3 345 5.40 1.9 0.03 0.3 1.6 0.5 1.0

4 320 5.40 1.7 0.03 0.3 1.5 0.5 0.9

5 298 5.40 1.6 0.02 0.2 1.3 0.5 0.9

6 277 5.40 1.5 0.10 0.2 1.2 0.4 0.8

7 258 5.40 1.4 0.10 0.2 1.1 0.4 0.7

8 240 5.40 1.3 0.09 0.2 1.0 0.4 0.7

9 223 5.40 1.2 0.08 0.2 0.9 0.3 0.6

10 207 5.40 1.1 0.08 0.2 0.9 0.3 0.6

11 193 5.40 1.0 0.07 0.2 0.8 0.3 0.5

Cumulative reserves (Bcfe) 3.8 10.9

Cumulative net income 10.9

Completed Well Costs ($MM) 4.0

Net income 6.9

After tax rate of return (assumes average gross reserves of 2.5 - 3 Bcfe per well and 20% royalty) 172%

company-operated wells in 2006 and 2007.The company continuesto expand its acreage in the Fayetteville Shale.

XTO is currently a participant in 40 wells, primarily drilled bySouthwestern. XTO will begin independently drilling its ownFayetteville Shale wells in 2007.

Contango Oil & Gas is continuing its investment in the play,which is of meaningful size in relation to the company’s market cap.Contango is committed to 87 wells with an average working interestof 15%. It plans to drill 10 more wells with an approximate 40%working interest in 2007. Contango was expecting 40 producingwells by year-end 2006.

Penn-Virginia Oil & Gas, with 13,000 net acres, recently spud itsfirst horizontal well,with a 70% working interest. It participated withSouthwestern in two other wells. Before the end of 2006, Penn-Virginia expected to drill two additional horizontal wells.

Storm Cat has identified six locations targeted for drilling by thesecond quarter of 2007. Storm Cat owns or controls 13,000 acres.Currently, the company is preparing for the wells, acquiring permits,pipeline access, and negotiating and securing drilling services.Recently, Storm Cat increased its position and agreed to acquire 340net acres in Cleburne, Conway and Faulkner counties.

Barnett-Woodford ShaleThis play has turned in mixed results to date. So far, some wells inthis area, primarily in Reeves and Culberson counties in far WestTexas, have been difficult to drill and complete. Sources indicate onerecent,unnamed well reportedly came in with a completed well costof $16 million.

Recent activity includes:• Carrizo Oil & Gas—Most of this company’s acreage is in the

Marfa Basin, close to acreage positions of The ExplorationCo., Continental Resources and Quicksilver Resources.Carrizo is talking to other companies about a group 3-D seis-mic shoot and is doing ongoing technical work. In southernReeves County, the company has participated in several wellswith mixed results. Water production has been a problem andthis is being analyzed. A portion of the Carrizo acreage is inEddy County, New Mexico, where there are no immediateplans except to observe industry activity.

• EnCana—This company is in negotiations with numerousindustry participants on farming out portions of its 650,000-acre position to speed the evaluation effort.

• Quicksilver Resources—This firm planned to drill a thirdBarnett-Woodford well before year-end and then complete allthree. There has been no mention of results so far.

• Southwestern Energy—The company is continuing comple-tion operations on its first two vertical wells. No results havebeen released.

Floyd ShaleOperators appear to be doing a good job holding their well infor-mation “tight” in the Floyd Shale play.

• Murphy Oil, Noble Energy—We understand these companiesdrilled five wells as partners and have had two additional wellspermitted but not yet drilled. Information is being tightly held.We understand that cores have been or are being analyzed.

• Carrizo Oil & Gas completed its 3-D seismic survey and is

currently processing the data. Carrizo shot its seismic, lined upa rig and hoped to spud a well by year-end 2006.

Devonian ShaleThis play has been a traditional target throughout theAppalachian Basin.

• Range Resources—Through November 2006, Range had drilled11 vertical and three horizontal Devonian Shale wells inPennsylvania.Four of the vertical wells have been completed andare producing favorably,with estimated reserve potential between0.6 billion cubic feet and 1 billion cubic feet per well.The fourthvertical well was recently brought on line at a peak rate of 1.2MMcfe a day, which is higher than the first three wells.

• By year-end 2006, Range anticipated having 10 vertical wellsand two horizontal wells on line. The company is workingtoward a significant expansion of the Devonian developmentprogram in 2007. The hope for expansion is up to 60 verticalwells and four horizontal wells. Range holds 314,000 net acresin this play.

• Equitable Resources—EQT has drilled, completed and istesting one well, and another well has been drilled and isawaiting completion. The company expected to have twomore wells drilled by year-end 2006. All are horizontal testson the Kentucky side of the play.

For more information, contact John White, analyst,[email protected] (713) 751-1638 �.



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Over the past two years,has assisted:

By Michael E. (Gene) Powell Jr.

Most production reports on the Barnett Shale play in theFort Worth Basin have relied on the cumulative data of the

Newark East (Barnett Shale) Field as reported by the Oil & GasDivision of the Railroad Commission of Texas (RRC), the oil andgas regulatory authority in the state. The Production Data QuerySystem is available at http://webapps.rrc.state.tx.us. That cumula-tive production total, however, only goes back to January 1, 1993,even though production began in June 1982.

The majority of the production has been in the Newark EastField, but the data does not represent the total production of theBarnett Shale throughout the Fort Worth Basin, because theBarnett now has production in 19 counties with wells spotted upto July 1, 2006 (Figure 1).

Early ProductionThe RRC data begins reporting cumulative field data as ofJanuary 1, 1993, whereas the now-Barnett Shale began producingin 1982. It has produced 25.3 billion cubic feet of gas and 44,543barrels of oil between 1982 and January 1, 1993.

The RRC allowed other Barnett Shale fields to be named until2002, when it became apparent this shale was a consistent geo-logical formation varying only in thickness and located in morethan 20 counties, at which time the state agency stopped naming

new fields in the Barnett Shale (Figure 2).By 2003, some 17 fields had been named in the Barnett Shale in

the Fort Worth Basin. Many of these smaller fields are surroundedby wells producing in the Newark East (Barnett Shale) Field;therefore, all 17 fields in the Barnett Shale need to be included backto 1982 to provide a more realistic look at the production.

Pending Production DataThe RRC requires a lease code to be assigned to a gas well, or tothe full lease in the case of an oil well, for that production to bereported in its field reporting system. However, there are a signifi-cant number of wells producing in Texas whose production is notbeing reported because of minor input errors by the operators.There has also been an increase in drilling in Texas in the past fouryears, but a decrease in personnel at the RRC’s Oil & Gas Division.This has added to the backlog in the Pending Production File andrepresents oil and gas output not yet officially reported.

The RRC did begin allowing operator and well searches of thePending Production File in 2006. This has allowed greater accessto that production data, which needs to be added to the otherreported data, to ascertain how much the Barnett Shale has actu-ally produced during any given period. It should be noted thatsome of the wells in the Pending Production File have producedas long as 18 months, so each time a search is made for a specificfield and time period, production data will have changed as inputerrors are corrected and as production moves from pending status

to the field reporting file.Our study of the Pending Production File data

from the PI/Dwights database of IHS Inc. forthe period studied and ending July 1, 2006,revealed 56.5 billion cubic feet of gas and153,741 barrels of oil produced from 558 wells.This is “pending” production data that will beadded to the final cumulative data.

Our study thus shows total production for theBarnett Shale of the Fort Worth Basin to July 1,2006, including all fields from 1982—includingthe pending production not yet reported in fieldsearches—is 2.2 trillion cubic feet of gas and 7.5million barrels of oil and condensate.

Our research shows 5,926 wells have con-tributed to the total cumulative production fromJune 1, 1982, to July 1, 2006. Average daily pro-duction for the month of June was 2.07 billioncubic feet of gas and 5,481 barrels of oil and condensate from 5,619 active wells.

The data shows the Barnett Shale Field is nowproducing 2 billion cubic feet per day, making itthe largest-producing gas field in Texas. It is alsothe second-largest producing gas field in theUnited States behind the San Juan Basin area of

SHALE GAS Barnett Shale


Figure 1. Barnett Shale producing counties in the Fort Worth Basin, July 2006. Source: IHS Inc.

BIGGER IN THE BARNETTAccording to this consultant, production in the Barnett Shale in the Fort Worth Basin is greaterthan earlier reports indicated.

New Mexico and Colorado, which includes coalbed-methane gasand tight-gas sands.

Recoverable Gas AssessmentsThe assessments of recoverable gas resources in the Barnett Shaleof the Fort Worth Basin have significantly grown each time a newstudy is made. We expect another increase when the next analysisis completed, due to the higher well density of horizontal wells(now using 20-acre spacing between laterals), and the greater useof simultaneous fracturing of horizontal wells.

The application of new technology should increase the percentageof recovery of gas-in-place from the current estimate of up to 15%.The first two estimates were from the United States GeologicalSurvey and the last was from Advanced Resources International Inc.in a study of U.S. unconventional gas made for the EnergyInformation Administration’s 2006 Energy Outlook in March:

1996 United States Geological Survey 3 Tcf2004 United States Geological Survey 26 Tcf2005 Advanced Resources International Inc. 39 Tcf �

Gene Powell has spent four decades in the oil and gas industry workingin management for a major, a large independent, as an operator with 10field discoveries to his credit and as a consultant. He has well interests inthe Barnett Shale and has sent out the Powell Barnett Shale Newsletter of

articles and studies via e-mail weekly at no charge since 2003. He can becontacted at [email protected]


SHALE GASBarnett Shale

Table 1. Barnett Shale Fields in the Fort Worth Basin January 1, 1982 to July 1, 2006.

Fields Oil (Barrels) Casinghead Gas Gas Well Gas Condensate (Barrels)(Thousand cubic feet) (Thousand cubic feet)

Newark East 1982 – January 1, 1993 25,306,238 44,543

Newark East January 1992 to June 2006 425,522 6,048,200 2,066,017,365 6,307,042

Cleburne 0 0 6,969,913 2

Saint Jo Ridge 553,827 2,140,491 0 0

Avondale 0 0 1,420,286 26

Jason Dvorin 0 0 247,134 0

Antioch 0 0 1,420,286 26

Rector 0 0 216,154 0

Bowie Northwest 18,226 182,412 0 0

Sanford Dvorin 0 0 159,411 0

Dubois 0 0 88,661 50

Mulliniks 0 0 57,075 0

Denton Creek 4,078 47,343 0 0

Bellevue 6,352 40,777 0 0

Jack County Regular 0 0 28,220 0

Cleburne West (Hancock Shale) 0 0 18,163 0

Wise County Regular 0 0 3,609 296

Lamkin-Hamilton 901 0 0 0

Totals 1,008,906 8,459,223 2,100,769,650 6,351,959

Figure 2. U.S. Geological Survey Province 50 Boundary, BendArch—Fort Worth Basin Regional Isopach Data, Barnett Shale. Source: Rich Pollastro, 2004

Oil (Bbl) Casinghead (Mcf) Gas Well Gas (Mcf) Condensate (Bbl) Total All Gas (Mcf) Total Condensate & Oil (Bbl)

1,008,906 8,459,223 2,100,769,650 6,351,959 2,109,228,873 7,360,865

RRC Pending Production File 56,508,728 153,741

Total Production Barnett Shale 2,165,737,601 7,514,606

Table 2. Barnett Shale Production in the Fort Worth Basin. All Fields—January 1, 1982 to July 1, 2006.

By Kent A. Bowker, George Moretti Jr. and Lee Utley,ShaleQuest Partners

During the past year, Southwestern Energy Co. and otheroperators (most notably Chesapeake Energy) have further

delineated the Fayetteville Shale play in the Arkoma Basin ofArkansas. Southwestern has also reported some excellent resultsfrom recent horizontal wells in the play utilizing water fracs. Forexample, the Southwestern Energy Grills No. 2-31-H made 95.5million cubic feet of gas in August 2006.

The Fayetteville appears to be maturing past the exploratoryphase in the initial fairway or core area of Conway, Faulkner, VanBuren, Cleburne and western White counties, with an averageestimated ultimate recovery for the latest horizontal wells in thisregion appearing to be above 1.5 billion cubic feet. However,there have been disappointing results so far in the eastern exten-sion of the play into the Mississippi Embayment, such as Lee,Woodruff, St Francis and eastern White counties.

As of November 2006, according to state records, there were 123 producing Fayetteville/Moorefield (more on theMoorefield later) wells in the core area of the play in Cleburne,Conway, Faulkner, Van Buren and western White counties.Southwestern (114), Chesapeake (8) and Yale Oil (1) operatedthe respective wells.

In addition, there were more than 250 active drilling permits(wells currently drilling, being completed, being tested or staked)for these counties.

In addition to Southwestern and Chesapeake, which are themost active players, companies with outstanding permits includeHallwood Petroleum, Maverick, Pathfinder, CDX Gas, AspectEnergy,Teepee (also known as Alta Resources, which has the par-tial financial backing of George Mitchell of Mitchell Energy &Development), J-W Operating, Edge Petroleum and DavidArrington. Shell Oil Co. has a large leasehold in the play but haselected, at least to this point, not to operate any of the wells inwhich it has a working interest.

In 2006, Chesapeake announced that about 700,000 of its 1 mil-lion acres were not currently prospective based on its disappointingdrilling results in the Mississippi Embayment-portion of the play.However, various companies have applied for more than 20 drillingpermits in Woodruff, St. Francis, Monroe, Phillips, Jackson, Lee andPrairie counties, all in the eastern (Mississippi Embayment) portionof the play.

GeologyThere is a general lack of industry knowledge about the potentialshale reservoirs in the Arkansas portion of the Arkoma Basin.Using our experience in the Barnett and other shale plays, we havecompleted an extensive geologic and petrophysical study of theFayetteville Shale. It soon became clear that the Moorefield,

which we divided into a lower and upper unit, was also a prospec-tive horizon.

Since we began our work, Southwestern Energy has completed atleast one well in the Upper Moorefield in Cleburne County. TheWoodford Shale, now prevalent in southeastern Oklahoma, has alsobeen tested in the basin, but we don’t believe there is sufficient gas-in-place to warrant a complete study at this time.

We correlated logs from all available wells (about 150) in the east-ern portion of the Arkansas part of the Arkoma Basin andMississippi Embayment. We also constructed nine regional cross-sections across the basin, and constructed 21 maps to help under-stand the geology of the Fayetteville and Moorefield shales.

In many ways, the stratigraphy and structural geology of theArkoma Basin are more complicated than in the Fort Worth Basin,making the exploration and exploitation of the Fayetteville andMoorefield shales more difficult than the Barnett.

One problem or misunderstanding is where exactly in the strati-graphic column the Fayetteville lies. In short, we agree with the stratigraphy data used by Southwestern Energy, and thinkthat the formational boundaries used by the Arkansas GeologicalCommission, though possibly technically correct in a biostrati-graphic sense, are not useful for geologists prospecting in the basin.

A quick examination of wireline logs across the relevant strati-graphic section shows that the higher gamma ray-higher resistivityshales are the prospective intervals, not the shale higher in the strati-graphic column (between the Fayetteville and the overlying Hale).

The Ouachita Thrust Belt is a common factor in natural gas pro-duction in these plays:

• Barnett Shale in the Fort Worth Basin;• Woodford and Caney shales on the Oklahoma side of the

Arkoma Basin;• Fayetteville, Moorefield and Chattanooga shales on the

Arkansas side of the Arkoma; and• Floyd/Neil shale in the Black Warrior Basin of Mississippi and

Alabama. (See related article elsewhere in this report).Without the emplacement of the Ouachitas and the resultant

heating events across these basins, there would be no gas productionfrom these reservoirs. The continental-scale thrusting events actedlike a series of squeegees, pushing hot, mineral-laden brines out infront of the thrust sheets.

This brine moved through the underlying Ordovician strata(e.g., the Ellenburger in the Fort Worth Basin) and heated theshallower rocks (Mississippian and Devonian shales) to a pointmuch hotter than would be expected with a “normal”Midcontinent burial history. Without this additional heat flow,many portions of these basins would not have made it into the gaswindow.

The highest heat flow was in the Arkoma Basin, probably becauseof its location at the apex of the Ouachita Trend. The lead-zincdeposits of the Tri-State mineral district of the southern Ozarks wereemplaced as a result of this hot-brine migration.

SHALE GAS Arkansas Shales

FAYETTEVILLE MATURINGA recent study shows how different the geology and petrophysics of the Fayetteville and Moorefieldshales are from the Barnett Shale.


Fayetteville ShaleIt quickly becomes obvious that the Fayetteville Shale is differentfrom the Barnett of North Texas. Most importantly, theFayetteville was deposited in a much different environment thanthe Barnett; and, hence, it’s restricted to a smaller area. Therewere abrupt facies changes during the time the Fayetteville wasdeposited, especially to the east toward the Embayment andsouth toward the Ouachita Thrust Belt, that create hazards forexploration for gas in this formation.

The thickest portion of the Fayetteville Shale is toward the northand northwest, at the outcrop belt. This is in direct contrast to theBarnett, where the thickest section is in the deepest portion of theFort Worth Basin, which is in front of the Muenster Arch inMontague County. This “upside down” thickness pattern, such thatthe thickest shale interval is toward the basin margin, gives someindication as to the depositional system responsible for theFayetteville Shale.

The Moorefield Shale lies just below the Fayetteville; a relativelythin limestone unit called the Hindsville separates them.We dividedthe Moorefield into a lower and upper unit, with the upper being themore perspective unit.

Petrophysical TraitsHistorically, critical petrophysical parameters have been difficult topredict in gas shales. Techniques developed through years of experi-ence in the Barnett Shale in the Fort Worth Basin were used here to

tie the limited core data to the more widely available log data.Modelswere developed to predict porosity, water saturation and gas-in-place(free and sorbed) in the Fayetteville, and upper and lower portions ofthe Moorefield shales. We have mapped these.

For the Fayetteville Shale study, we began by digitizing the per-tinent log data for more than 120 wells. Preliminary formationcorrelations were made to aid in analysis. The models requiregamma ray, bulk density and resistivity logs. The gamma ray andbulk density data were normalized to account for calibrationissues. We patched the bulk density data to eliminate false read-ing because of washouts. Resistivity inversion analysis, performedon old E-log data, old induction data and dual-laterolog data,eliminated discrepancies because of different generations of resis-tivity tools. The cleaned and normalized log data enabled moreconfident stratigraphic correlations.

Modeling of petrophysical parameters is based on available coreand cuttings data, including standard gas shale core data for twowells, the Thomas 1-9 and the Thomas 1-16 (both drilled bySouthwestern Energy) and geochem analysis from cuttings on 45 wells.

We trained and confirmed neural network models to calculateporosity and total organic carbon (TOC) using the core data. TheTOC model was further confirmed using the cuttings-derivedgeochem data.We developed deterministic models to calculate watersaturation and gas-in-place, comparing these results to publishedcore data. �

SHALE GASArkansas Shales



SHALE GASEmerging Play

By Kent A. Bowker, Bowker Petroleum LLC

During the past year and a half, there has been a slow, butcontinuous, industry effort to explore for and develop the

gas resources of the Floyd Shale in the Black Warrior Basin. Theblack-shale interval of the Floyd, which is the Alabama name forthe formation, is called the Neil Shale in Mississippi, but they arethe same prospective shale interval.

Recently a high-profile deal drew more attention to the play, when Chesapeake Energy Corp. entered Alabama by forming a 50-50 area of mutual interest (AMI) with Alabamaexpert Energen Resources, the E&P arm of the local utility.Chesapeake announced a $90-million deal with Energen that involves the latter company’s position in the Floyd Shale play. Chesapeake will earn a 50% interest in Energen’s200,000-net-acre position in the Alabama portion of Black Warrior and Appalachian basins. They said the AMI they have formed will focus for the next 10 years on new leases and operations in the area.

In light of this deal, Chesapeakenow says it has accumulated 4.25 mil-lion net acres of prospective shaleleases “in every major shale play eastof the Rockies.”

GeologyThe Floyd Shale is the stratigraphicequivalent of the Fayetteville andBarnett shales, but in its depositionalhistory, it is more akin to theFayetteville of Arkansas. In a fashionsimilar to the Fayetteville, the organic-rich black shale facies of the Floyd appears to grade laterally into leaner, and probably non-prospective, shale facies in various portions of the basin.

The organic-rich portion of the Floyd ranges up to about 150feet thick and is about 4,000 to 10,000 feet deep across the play.Understanding the distribution of the organic-rich facies withinthe Floyd will be a key factor —along with the structural geology,well design and well-completion design—in the eventual successof the play.

There do not appear to be any karst features (sinkholes) pres-ent in the Black Warrior Basin. These are common in the FortWorth Basin, however, and are considered a hazard to be avoidedin the Barnett Shale play under way there.To detect karst featuresand faults, operators conduct 3-D seismic surveys in this play.Faults are present in the Black Warrior Basin, but they don’tappear to be so abundant as to cause more than a slight distrac-tion in the development of the Floyd Shale play once they aremapped accurately.

Activity BeginsActivity in the play began in mid-2005 with vertical wells drilled byDenbury Resources (a long-time North Texas Barnett veteran) inMississippi and Murphy Oil Co. in Pickens County, Alabama.Denbury has recently completed a horizontal well in southern LamarCounty,Alabama.Elysium Energy (now acquired by Noble Energy),Cabot Oil & Gas, Anadarko Petroleum, Wagner and Brown, andDavid Arrington have drilled wells in the Floyd Shale.

Privately held Arrington’s effort has been the most aggressiveto date with a vertical frac-mapping well. According to reportsfrom the field, the Floyd Shale was cored in this well, a verticalpilot well, and an offsetting horizontal well was being drilled atpress time. These wells are in northern Lowndes County,Mississippi. Arrington is apparently the largest lease holder in theplay: aside from leasing for its own account, Arrington acquiredNoble’s position in north Pickens and Lamar counties, and madeanother large purchase of acreage in Alabama and Mississippi.

Murphy Oil’s acreage position appears to be across a large por-tion of the basin, based on the location of wells it has permitted.

No production has been reportedfrom the five vertical wells Murphyhas drilled in Pickens County, thoughthree of them are reported as currentlytesting following perforating andfracing.

In mid-November 2006, Murphyannounced a major reorganization ofits E&P management, moving allworldwide E&P activities under onegroup based in Houston. It will beinteresting to see if this impacts thefirm’s Floyd Shale efforts.

Anadarko recently drilled a pilot well in Clay County,Mississippi, with a possible horizontal kick-out to follow fromthis wellbore.

Anadarko recently finished drilling a pilot well in Clay County,Mississippi, with a possible horizontal kick-out to follow fromthis same wellbore.The company plans to drill additional wells inthis portion of the Floyd Shale play, its only company-operatedeffort in a domestic shale play in many years. (It also holdsacreage in the periphery of the Texas Barnett Shale play thanks toits recent acquisition of Western Gas Resources.)

Also active in the play with acreage positions are Edge Petroleum,Bankers Petroleum, Lario Oil & Gas, Carrizo Oil & Gas andMarlin Energy.

Because activity is new, few details are available, but operatorscontinue to lease. �

Kent Bowker is a principal with ShaleQuest Partners LLC andBowker Petroleum LLC. This is excerpted from a new study the firmhas done on the Floyd Shale.

THE FLOYD/NEIL SHALE In the Black Warrior Basin of Alabama and Mississippi, operators are trying to develop the potential of a new shale play.

In a fashion similar to theFayetteville, the organic-rich black

shale facies of the Floyd appears to

grade laterally into leaner, and probably

non-prospective, shale facies in various

portions of the basin.

By Randy LaFollette and Gary Schein, BJ Services

The Barnett Shale of the Fort Worth Basin has been recog-nized for some time as a major unconventional gas resource

play, that is, a continuous accumulation requiring advanced tech-nology for production. Since the Mitchell CW Slay No. 1 wellwas drilled and completed in 1981, the Barnett play has seen sig-nificant changes in understanding the reservoir, technologiesapplied and success.

What are some of the lessons learned from the standpoint of aservice company actively fracturing Barnett wells?

Understanding the ReservoirShales are sedimentary rocks defined by their particle size range.Just as sandstone is defined as a clastic sedimentary rock havingmost of its grains about the size of sand, shale has most of its par-ticles about the size of clay.True shales exhibit the property of “fis-sility,” splitting along closely spaced horizontal planes of weaknessas a result of alignment of platy minerals, the micas. A clastic sed-imentary rock fitting the particle-size range of shale, but lackingthe property of fissility, is termed a mudstone or claystone.

None of these rocks is defined by their mineralogy, and they canall have variable mineral contents, which affect reservoir quality in

the fractured shales by the presence of higher percentages of themore brittle minerals, especially quartz. Such rocks have potentiallymore natural fractures than rock with higher clay or carbonate min-eral content. Variability in shale particle-size ranges may affectmatrix permeability, which is low in the extreme.

Matrix permeability numbers commonly referenced in BarnettShale discussions range between 10-7 and 10-9 Darcies.Interbeds or laminations of silt- and sand-sized particles mayradically improve local matrix permeability. Open, or partly open,natural fractures, where present, improve system permeability.

There is a vast difference between “continuous accumulation”and “constant” or even “constantly and predictably varying” reser-voir properties. While the Barnett is a continuous accumulation,critical reservoir properties are far from constant, both verticallyand laterally.

In the fractured gas shale and tight sandstone worlds, gas-in-place (GIP) numbers receive a lot of attention and tend to beextremely large numbers that get people excited. GIP is funda-mentally driven by porosity, thickness, drainage area, gas satura-tion and reservoir pressure. While GIP numbers are difficult to quantify, only a small fraction, about 10% to 20% of the gas in the Barnett, is recoverable with present technology and techniques.

Deliverability, or gas rate, is driven by five “reservoir-only” parameters: permeability, thickness, reservoir pressure,reservoir fluid viscosity and drainage radius. Additional drivingparameters are wellbore flowing pressure, wellbore radius andskinparameters that can be affected by drilling, completion andstimulation practices.

The Barnett is a variably productive reservoir. Figure 1 bubble-maps sweet and not-so-sweet Barnett producing areas. The mapshows vertical Barnett wells having at least seven months of pub-lic production data in the IHS database and readily delineates theoriginal Barnett core producing area. Based on the public data asof October, the sweet spots in which the best 10% of vertical wellshave been drilled have been restricted to specific areas withinDenton, Wise, Tarrant and Johnson counties. Changing the mapto show the best and worst 10% of those wells highlights theirgeographic separation and strongly implies variation in criticalreservoir properties.

One of those key critical reservoir properties is hydrocarbonliquids. Figure 2 shows normalized six-month Barnett oil cumulative production. Oil production increases to the north-west, and the core area gas-producing sweet spots occur where oilproduction is least. A map of Barnett water-to-gas ratio shows asimilar trend, indicating that produced liquids are not good whencombined with gas production in very low-permeability rocks.

Other factors also drive the locations of these sweet spots toinclude degree of natural fracturing, faults, Ellenberger karsting(dissolution features) and the Viola Limestone fracture barrier.Figure 3 shows the vast majority of the best vertical wells were

SHALE GAS Barnett Shale Geology


Figure 1. The best Barnett Shale vertical gas wells are shown inorange or red, the lowest producers are in purple.

UNDERSTANDING THE BARNETT SHALE Now that nearly 6,000 wells have been drilled, the industry has better knowledge of what makesthe Barnett Shale tick.

drilled in areas where the Viola Limestone underlies the Barnett,resulting in a hydraulic fracturing barrier between the Barnettand wet Ellenberger. The Barnett is not a simple formation with

a set of constant reservoir properties, and this is combined withvarying geomechanical hurdles to overcome. This implies tech-nology needs may vary as well.


SHALE GASBarnett Shale Geology

Figure 2. Normalized six-month cumulative oil production showslow oil output in the core sweet spots for gas.

Figure 3. Best 10% and worst 10% of vertical gas producers are com-pared to the Viola Limestone (turquoise) that underlies the Barnett Shale.

TechnologiesTwo of the major advanced technologies critical to expanding Barnettsuccess have been horizontal drilling and slick-water fracturing. Ultra-lightweight proppants may also play a role, particularly as new, higherstrength versions come out of the research laboratories and into thefield. Simultaneous fracturing of offset horizontals is another newertechnology showing promise in the Barnett.

Figure 4 is a timeline of Barnett vertical and horizontal well normal-ized six-month cumulative gas production. White data points repre-sent vertical wells, and blue data points represent horizontal wells.Note that horizontal drilling in the Barnett was tried one time in1992. Production at the time was worse than that of most verticalwells, so horizontal driling was not attempted again until 1998. Six to10 more horizontal Barnett completions would be required before pro-duction was considered acceptable and horizontal technology begainto be deployed widely in the Barnett. The lesson seems clear: a singlepoor result early on delayed by several years what was later proven tobe a sound technology.

Horizontal drilling—After its somewhat rocky start, horizontaldrilling became a game-changing technology in the Barnett in 2003.Figure 4 also shows the best vertical wells produce about 350,000 Mcfof gas during the first full six months of production. This compareswith the best horizontal wells producing nearly 1 billion cubic feetduring the same normalized time period.

Producing more gas from fewer wellbores was important, but hori-zontal drilling had another even more important contribution to make:it permitted successful Barnett wells to be drilled in areas where verti-cal wells were poorly performing. Horizontal wells that produced aswell as or better than the best core area vertical wells could now bedrilled well away from the core area, generating successes in southernTarrant and Johnson counties.

Horizontal well length and azimuth have been correlated to Barnettgas production in specific areas. Based on the publicly available pro-duction data, optimum horizontal well lengths are between 3,000 and4,000 feet, including the build section.

Early production data largely from the core area and from JohnsonCounty indicated optimum well azimuth was between 120° and 140° or300° and 320° in those areas. This relationship is not apparent for allBarnett producing areas. Drilling along 120° to 140° or 300° to 320°approximately parallels the main natural fracture sets and allows place-ment of transverse hydraulic fractures, creating maximum surface area forgas production from very low permeability matrix into an interconnectednetwork of natural and induced fractures and then to the wellbore.

It is important to recognize that simply drilling and completing hor-izontal wells in the Barnett does not guarantee success. Many horizon-tal Barnett wells have been drilled in areas of poor reservoir quality orhave had drilling, completion or other operational problems resultingin poor production rates.

Fracturing—Slick-water fracturing was first applied to the Barnettbetween 1997 and 1998 and slick water soon became the Barnett frac-turing fluid of choice. Slick water is a much simpler fracturing fluidthan the cross-linked gels. Where these gels are complex mixtures ofwater, polymer, cross-linker and buffer, slick water is made up of water

SHALE GAS Barnett Shale Geology



SHALE GASBarnett Shale Geology

and friction reducer. Both fluid types may also contain additivessuch as biocide, surfactants and scale inhibitors, depending onspecific treatment requirements and goals.

The changeover from large cross-linked gel fractures savedBarnett operators an estimated 30% of frac cost without sacrific-ing production.

Typical vertical well frac designs are based on between 2,200and 2,400 gallons of fluid per foot of gross height. The pad com-prises between 30% and 40% of total fluid, with 50% of the slurryusing proppant concentrations between 0.1 and 0.65 pounds pergallon with the final 10% of the slurry ramped up to 2 pounds pergallon. Current practice calls for Ottawa sand in 40/70 mesh and20/40 mesh size ranges, with some operators in some areaspumping mainly 100-mesh sand and tailing in with 40/70. Jobsare pumped at injection rates between 40 and 85 bpm.

Vertical wells in areas where the Barnett is thin or the lowerViola frac barrier is questionable or absent will be pumped atrates on the low end of the range. Barnett fractures targetingthicker zones have the option of being pumped at higher rates.

Typical horizontal well fracture designs call for multi-stage,0.8- to 1.5 million gallon treatments of slick water per stage withbetween 10% and 12% pad, 75% and 80% proppant in the 0.1 to0.65 pound per gallon concentration range, and the final 10%ramped up to 2 pounds per gallon. Some Johnson County wellshave been fractured with as much as between 7- and 8 milliongallon jobs. Horizontal wells are commonly fractured down cas-ing at injection rates between 70 and 100 bpm range for 51⁄2-inchpipe and 150 to 200 bpm for 7-inch pipe.

The goals of hydraulically fracturing the Barnett are to create a maximum amount of conductive surface area deep in the reservoirand provide a series of relatively high conductivity flow paths tothe wellbore. There are four ways to transport proppant deep intothe reservoir: increasing injection rate, increasing viscosity of thefracturing fluid, decreasing proppant mesh size and decreasingproppant specific gravity.

Increasing injection rate can be useful, but may not be desirablein areas where the frac may tend to grow downward into the wetEllenberger. Increasing viscosity by using cross-linked gels willcarry more proppant and transport it further than slick water.However, cross-linked gelled water may also yield a less complexhydraulic fracture with less surface area for gas production andcosts significantly more than slick water. Decreasing proppantmesh size has been a trend for some time and seems to providesome benefits. Smaller diameter proppant particles will enter nar-rower fractures than coarser materials and require less forwardvelocity to keep them moving.

The lower specific gravities of ultra-lightweight proppants,such as BJ LiteProp materials, also appear useful in certainBarnett applications. The story of ultra-lightweight proppants isnot yet fully written as early generations of these materials did nothave the crush resistance necessary for application across much ofthe Barnett. Newer generations of the LiteProp family of prop-pants may see widespread use in the future.

Simo-FracsThe most recent trend in Barnett fracturing is the simultaneousfracturing (simo-fracs) of paired offset wells. The theory behindsimo-fracs is to minimize intrusion of frac fluid and proppantfrom either well into the other as a result of high-induced stressescaused by frac slurry injection. The method is too new to be ableto say with certainty that it results in a long-term productionimprovement over fracturing each well separately and at differenttimes. However, where the production data exists and can becompared with non-simo-frac offsets, the method appears tohave promise.

In one comparison of normalized six-month cumulative gasproduction in central Tarrant County, the simo-frac wells are pro-ducing significantly more gas per foot of lateral than the offsetsthat were not simo-frac’d. Other simo-frac’d wells are showinghigher production than their offsets in the short term. Time willtell whether simo-fracturing is a game-changing technology inthe Barnett, but initial results point to a potentially promisingtechnology. �

Randy LaFollette is BJ Services manager, applied geoscience, workingfrom the research and engineering campus in Tomball, Texas. He is ageologist with 29 years experience in the industry and has worked infield, region and research level positions.

Gary Schein received a bachelor’s of science degree from NorthernArizona University in 1978 and has worked in well completions and stimulation for more than 28 years. He has also worked in research and development, technical support, marketing and field engineering positions.

Figure 4. In this production timeline, the blue dots are horizontal wells, a game-changer that greatly increased Barnettgas production.

By P. Jeffrey Brown, William J. Haskett and Patrick Leach,Decision Strategies Inc.

Unconventional resource plays are one of the hottest topics inthe oil and gas industry today. Potentially lucrative economic

engines, these plays were often considered drilling hazards in thepast.Today, the combination of high product prices and improve-ments in completion technology has thrust these unlikely butstrategic accumulations to the forefront of domestic explorationand exploitation.

However, evaluating investment decisions associated with theseunconventional opportunities requires a radically differentapproach from that used for traditional plays.

There is no universal definition of an unconventional resourceplay. In this article, resources such as tight gas, gas- and oil shaleas well as coalbed methane are included under the umbrella ofunconventional resources. The following chart summarizes dif-ferences between play types and how they are analyzed.

Decision PointsThe operator of an unconventional play should be mindful ofdownside risk throughout the life of the program. As such, thereare three principle decision points for the early exit (off ramp) ofthe project (Figure 1). In chronological order they are:

Off Ramp 1: Play or Exploration Risk—If the initial welldrilled into an unconventional play shows a geologic or technicalfailure that all other locations are likely to share, then there is nological reason to drill further locations; the play should be aban-doned. Often, a small number of failures must be drilled before ashared risk element is identified as the cause of the failure.Additionally, it may be determined through initial drilling thatthe productive horizon is unreachable with current technology tothe extent needed to achieve a viable chance of production.

Off Ramp 2: Pilot Failure—Unconventional ventures almostalways require the execution of one or more pilot programs toprovide initial rate and producibility data. Such pilots supplynotoriously imperfect information. The convergence of pilot

results to eventual program results depends on anumber of elements, including the number ofpilot wells drilled and tested.

Most of the learning in a pilot is achievedwithin the first few wells. The objective is to drillthe minimum number of wells needed to providea reasonably correct assessment of the entire pro-gram. Beyond this number, the incremental learn-ing per well is insufficient to justify theincremental cost.

When we create a probabilistic assessment foran exploitation program, we can designate athreshold average recovery per well for the testpilot. A full project cash flow is then simulatedbased on success-case activity levels, and the resultof each iteration is checked in hindsight. Eachiteration will have one of four possible, discreteoutcomes.

A pilot program is successful if it delivers cor-rect information, whether positive or negative.The ability of the pilot program to provide a cor-rect prediction of the profitability of the programis called pilot effectiveness. It is the sum of truepositive and true negative probabilities.

Pilot EffectivenessPilot program results are tracked based on differ-ent pilot sizes (from one to 20 wells). After a largenumber of simulated passes through the program,a stable picture of the predictive capacity of differ-ent pilot sizes is achieved. An example of results isshown in Figure 2. Often, the optimal number ofwells shows as an inflection point on the plot of

SHALE GAS Unconventional Resource Exploitation


DECISION-MAKING FOR UNCONVENTIONAL RESOURCES Understanding value and risk leads to better decisions, but in unconventional plays, the processmust be handled differently.

Conventional Unconventional

1. Hydrocarbons are housed in discrete accu-

mulations. For a variety of reasons, the

majority of the available containers will

prove to be totally dry. (Global commercial

success rate has remained remarkably consis-

tent at about 25% since the 1960s).

Hydrocarbons are ubiquitous. A high per-

centage of locations will find flowable gas.

The assessment of geologic chance is much

less important for unconventional plays,

having a significantly lower impact upon

variations in predicted results.

2. The basic units of natural measure for vol-

umetric analysis for traditional targets

are individual prospect volumes, or, at the

play level, the characteristics of field esti-

mated ultimate recovery for known (or

future) discoveries.

Productive boundaries extend beyond the

limits of individual company acreage hold-

ings. A cell is the basic, repeatable unit of the

play, reflecting the expectation for what each

well or well set will recover during its life—its

estimated ultimate recovery. Production and

cash flow can be modeled for each location

and aggregated as part of the simulation of

an exploitation program.

3. The key driver in economic analysis is gener-

ally uncertainty in success case volumes.

The uncertainties multiply: initial production

and decline rates, mechanical efficiency,

costs, acreage capture, strategy (and

acreage costs) and the timing of the success

program can dominate the analysis.

4. When a prospect is tested, the decision to

proceed (or not) usually hinges on the results

of the initial test well. The decision to pro-

ceed in a play, such as whether to continue

exploring, occurs after an initial test program

for a few prospects.

The key development decision depends on

test pilot program results and how represen-

tative the pilot results are of the future

development.

pilot effectiveness versus number of pilot wells. The ability tooptimize pilot size may save millions of dollars in well expense ona single project.

The pilot decision can be tested against other criteria, forinstance, the average initial potential of wells in test program,but we have found that estimated ultimate recovery (EUR) perwell provides the most robust predictions.

Off Ramp 3: Mid-point Program Test—At a certain point inthe program, it is important to stop and assess its projected eco-nomic benefit. Empirically, this seems to be when 20% to 30% ofthe intended development program has been completed, given apositive pilot response. Exiting at this point eliminates the signif-icant loss that could result from continuing with a developmentprogram that is economically unprofitable.

Fully probabilistic cost assessments are necessary to provide asound basis for the critical decisions and acreage strategy for theunconventional opportunity. Once a template is established, it iseasy to run sensitivities or model different levels of fiscal exposureto see the impact of variable inputs. This sort of testing allowstime, people and capital to be allocated to the appropriate activi-ties to maximize the potential for success.

Interpreting ResultsSeveral runs of the stochastic project simulation are usually required toget a good picture of the unconventional project at hand, as well as theoptions available to the E&P company.The first run of the assessmentmodel should be unconstrained, using no minimum pilot size or min-imum mid-point criteria (Figure 3).This provides an “NPV Swarm,”(net present value), which is a cross-plot of project NPV versusexpected average EUR per well, which is used to determine an appro-priate pilot minimum-success test criterion.

In Figure 3, each symbol represents one full-cycle cash flow analysisof an exploitation program (one iteration of the model), where full-project NPV is plotted against the average EUR for all wells modeledon that iteration.

All outcomes in which the average recovery per well is less than 1.7billion cubic feet per well result in a loss, and all outcomes greater thanabout 2.4 billion cubic feet per well result in a profit. Outcomesbetween these end-members are in the zone of uncertainty, in whichthe investment can result in a profit or a loss.

The assessment should be rerun, testing against a pilot threshold(perhaps 2 billion cubic feet per well in this example), to determine howoften the pilot will lead the company down the correct decision path.

After a significant number of wells has been drilled,a “mid-programtest” may be applied. If the wells drilled to date have not, on average,met the minimum threshold, the program is stopped. The mid-pro-gram test eliminates the downside outcomes from inaccurate pilotresults.This is the “elimination of pilot false positive”exit point shownpreviously in Figure 1.

Figure 4 shows an input scenario identical to that in Figure 3,but towhich a pilot and mid-program “hard stop” have been added to theanalysis, showing the impact of disciplined decision-making upon theexpected profitability of the play. Note the cluster of outcomes locatedjust below the $0 NPV line, representing iterations where the programwas stopped because of disappointing pilot (or mid-program) resultsresulting in abandonment of the venture.

While this decision leads to abandonment of some outcomes,whichmight have proved profitable, it protects against (and eliminates) mostof the spectacular fiscal failures.This results in a significant increase infull project expected value.

Other OutputsStandard output metrics for unconventionalplays are similar to those from conventionalopportunities, such as the full probabilisticrange for success case aggregate costs, vol-umes and value, and project efficiency. Anintegrated evaluation method captures thefull range of uncertainty, not only for vol-umes but also for cost, time and rate inputs,and project-specific outputs can be extractedfrom the results.

Aggregated production profile results canprovide a true probabilistic basis for facilityand/or other infrastructure utilization.

A fully probabilistic approach providesmanagement with more useful informationthan does a deterministic analysis.

SHALE GAS Unconventional Resource Exploitation


Figure 1. The four stages of unconventional projects with threeearly exit points for downside risk mitigation.

Figure 2. Pilot Effectiveness Plot.

ConclusionUnconventional resources offer a set of challenges not usuallyencountered with more traditional opportunities. Unlike standardprospect and play risk analysis, geologic chance is not a majorissue. Estimates of initial production, decline rates, mechanicalefficiency and success planning dominate the analysis, rather thanvolumetric determinations.

A fully stochastic business value chain context is the best wayto assess the full spectrum of potential economic outcomes of anunconventional play. This not only provides a valid approach for

value assessment, but also illuminates risk and offers mitigationpossibilities. Such an evaluation provides management with theinformation and strategic insights needed to make good invest-ment decisions. �

Jeff Brown, Bill Haskett and Pat Leach are with Decision Strategies Inc.Collectively, they have 80 years of oil and gas experience, each beginning hiscareer with a major oil firm before moving to the consulting field. DecisionStrategies Inc. is a leading provider of strategic advice to the oil and gas,chemical and transportation industries.


SHALE GASUnconventional Resource Exploitation

N E T H E R L A N D , S E W E L L & A S S O C I AT E S , I N C .

NSAI has extensive geoscience and engineering experience in the

Barnett Shale. Our experts have invested thousands of hours working on

Barnett and other shale projects for our clients. We have a 44-year history

of delivering independent reserve reporting to the E&P industry and the

financial markets and are uniquely qualified to be your Barnett Shale expert.

Our clients get the NSAI name and our team of experts.

We think they get the very best.

Offices in Dallas and Houston

Dallas 214.969.5401 Houston 713.654.4950

www.netherlandsewell.com

IF IT’S HAPPENING IN THE BARNETT SHALE,

CHANCES ARE WE’RE INVOLVED

B e c a u s e T h e r e I s A D i f f e r e n ce

Figure 3. Cross-plot of full project net present value versus theaverage estimated ultimate recovery (EUR) per well.

Figure 4. Cross-plot of full project net present value versus average esti-mated ultimate recovery per well with pilot and mid-program thresholds.

By Taryn Maxwell, Editor, A&D Watch

As extraction technology continues to improve, areas of theU.S. that were once thought to contain resources that would

never see the light of day are now considered some of the mostprolific and popular plays. One such play is the shale.

In the 1980s, when George Mitchell, founder of MitchellEnergy & Development Corp., began to work in the BarnettShale near Fort Worth,Texas, shale gas was but a glint in his eye.Today, companies are clamoring to get a piece of the Barnett, butit is Mitchell’s legacy, now a part of Devon Energy Corp., thatcontinues to hold the largest amount of acreage in the play.

“As the shale plays have some success, the deals get pricier,”says Brad Foster, vice president and general manager of DevonEnergy’s central division. “That’s where you do very well as afirst-mover. If you can be one of the first guys to have the visionand the recognition to get into a play before the acreage costsand the royalty costs go up, you can put a nice acreage positiontogether and make things happen. Devon had the first-moverposition in the Barnett. We recognized early on that shale playswould have a long-term impact onthe U.S. gas market.”

First-mover advantage is so impor-tant in the shale plays because oncethese plays become economical andmore valuable, those who hold theacreage are unlikely to sell it. Shaleacreage doesn’t change hands often,but when it does, the cost can be substantial.

Such was the case on June 29,2006, when Devon completed itspurchase of Chief Holdings LLC forsome $2.2 billion, further cementing its top position in theBarnett Shale.The company’s properties added estimated provedreserves of 617 billion cubic feet of gas equivalent and some169,000 acres to Devon’s leasehold in the Barnett.

“Chief had a lot of acreage that was undeveloped,” says Foster.“We had been very successful in going in and developing ouracreage position in the Barnett Shale over the last three or fouryears, and we feel comfortable that there is still tremendousupside in the play.”

Another heavy-hitter in the Barnett Shale is ChesapeakeEnergy Corp., which also has holdings in all of the major shaleplays east of the Rocky Mountains, including the WoodfordShale, the Fayetteville Shale, the New Albany Shale, and variousshale plays in Appalachia and Alabama, says Tom Price, seniorvice president of corporate development. Despite using its shaleknowledge all over the U.S., the company continues to focus onthe Barnett.

“We focused on the Barnett due to the relative consistency of

the formation, the repeatability of drilling success, the attractivefinding and development costs, and the company’s land expertisewhich allows Chesapeake to tackle formidable land problemsthat most other companies would be intimidated by,”Price says.

Chesapeake was very active in shale M&A in 2006, closing some$1.65 billion in deals in the Barnett Shale, including an agreementto lease 18,000 net acres underlying the Dallas-Fort WorthInternational Airport, the purchase of 1.5 trillion cubic feet of gasequivalent of proved and unproved reserves from Four Sevens OilCo. Ltd. and Sinclair Oil Corp., and the purchase of acreage fromseven private companies. Price says the company will continue tobe active in the acquisition arena in 2007.

Another shale play that has slowly begun to increase in popu-larity next to the Barnett is the Woodford Shale in southeasternOklahoma. Newfield Exploration Co. holds the first-moveradvantage in this play, but Devon is cautiously moving forwardwith its position of some 90,000 acres. It planned to exit 2006 with four rigs running there and is regarding the play with cautious optimism before moving forward with potentialacquisitions.

“We’re just starting to get a signif-icant data set together,” Foster says.“The problem with shale plays is thatyou need time to put wells on pro-duction to begin to understand whatyour decline rates are going to be.The longest a well in the Woodfordhas been on production for us hasbeen about a year.”

The Alabama shales are also begin-ning to grow in popularity, withChesapeake recently announcing apartnership with Energen Resources

Corp. after Energen sold a 50% interest in its 200,000 acres invarious shale plays in Alabama. The companies plan to form anarea of mutual interest on the acreage to develop shale playsthroughout Alabama.

As companies get involved with shale plays, they become increas-ingly aware they are operating in a play unlike any they have seen.

“The hardest thing about operating in the shale is the conven-tional wisdom you learned in college and in the oilfield over theyears doesn’t necessarily work in the shale,” Foster says. “You almosthave to retool your skill sets and your way of thinking because itdoesn’t always work the way conventional reservoirs work.”

Price says the difficulties that arise operating in the shales are no different than those that arise working anywhere else.

“Ensuring the various constituent interests are educated about the drilling process, the limited environmental footprint,the benefit to the community at large and maintaining closecommunication with elected officials are the most difficultthings,” he says. �

SHALE GAS Shale M&A


FIRST-MOVER ADVANTAGEWhen it comes to shale M&A, it’s usually the first-movers that hold all the cards.

Ensuring the various constituent interests are educated about the drilling process, the limited environmental footprint,

the benefit to the community at large and maintaining close

communication with elected officials are the most difficult things.

— Brad Foster, Vice President, General Manager, Devon Energy’s Central Division

SHALE GAS


Shale M&A

2006 SHALE M&A

Est. Value ($MM) Buyer/Surviving Seller/AcquiredEntity or Merged Entity Quarter Comments

$2,200 Devon Energy Corp. Chief Holdings LLC 2 Purchased assets in the Barnett Shale, Texas, gaining proved reserves of 617 billion cubic feet equivalent.

$845 Chesapeake Energy Corp. Four Sevens Oil Co. Ltd.; 2 Bought 39,000 acres in the Barnett Shale, Texas, Sinclair Oil Corp. gaining production of 30 million cubic feet equivalent.

$796 Chesapeake Energy Corp. Seven private companies 1 Acquired assets in Barnett Shale, South Texas, Permian Basin, Mid-continent and East Texas, gaining proved reserves of 264 billion cubic feet equivalent.

$435 Range Resources Corp. Stroud Energy Inc. 2 Bought company, gaining assets in Oklahoma and Texas with production of 33 million cubic feet equivalent per day, half of which is from Barnett Shale acreage.

$181 Chesapeake Energy Corp. Dallas/Fort Worth 3 To lease 18,000 net acres prospective for Barnett Shale International Airport gas, gaining possible reserves of 470 billion cubic feet.

$110 XTO Energy Inc. Peak Energy Resources 2 Bought company, gaining Barnett Shale assets in Hood, Parker and eastern Erath counties, Texas, with proved reserves of 64 billion cubic feet.

$87 Chesapeake Energy Corp. Undisclosed 2 Bought unproved Barnett Shale acreage.$30 Bankers Petroleum Ltd. Vintage Petroleum 2 Bought shale gas acreage in various U.S. basins.$28 Petrosearch Energy Harding Co. 1 Formed a joint venture in the Barnett Shale.

$27.5 Cadence Resources OIL Energy Corp. 1 Bought producing assets in the Antrim Shale gas play.$11.5 TBX Resources Earthwise Energy Inc. 3 Bought assets in the Barnett Shale.$5.5 Dune Energy Inc. Voyager Partners Ltd. Bought Barnett Shale leaseholds in Denton County, Texas.$5 Parallel Petroleum Undisclosed 1 Bought interests in the Barnett Shale.

$3.4 Approach Resources Inc. Hallador Petroleum 2 Bought an Albany Shale prospect in Kentucky.$3 Nitro Petroleum Inc. JMT Resources Ltd. 1 Bought a 50% interest in JMT’s projects.

$1.2 Lexington Resources Inc. Dylan Peyton LLC 1 Bought Barnett Shale acreage in Comanche City, Texas.NA Ascent Resources Plc Norwest Energy 3 Bought interests in the West Virginia gas shale project.NA Cadence Resources Undisclosed 1 Bought 64,000 acres in the New Albany Shale.NA Cadence Resources Undisclosed 2 Bought interests in the New Albany Shale.NA Cadence Resources Undisclosed 2 Bought interests in the Antrim Shale.NA Chesapeake Energy Energen Corp. 2 Bought 140,000 acres in the Floyd Shale.NA Chesapeake Energy Undisclosed 2 Bought 150,000 acres in the Barnett/Woodford Shale.NA Continental Resources The Exploration Co. 2 Bought interests in the Marfa Basin in the

Barnett/Woodford Shale.NA Crimson Exploration Inc. Core Natural Resources 1 Bought 22,000 acres in the Barnett/Woodford play in

Culberson City, Texas.NA Energen Corp. Undisclosed 2 Bought 140,000 acres in the Floyd Shale.NA Forest Oil Undisclosed 3 Bought interests in the Barnett Shale.NA Ignis Petroleum Rife Energy Operating Inc. 1 Bought interests in the Barnett Shale play.NA Irvine Energy Metro Group 3 Bought interests in the Chattanooga Shale in Kansas.NA Marathon Oil Corp. Undisclosed 2 Bought 200,000 acres in the Bakken Shale play in North

Dakota and Montana.NA Maverick Oil & Gas Inc. RBE LLC 1 Bought a 13.33% interest in RBE LLC.NA Morgan Creek Energy Pathways Investments 3 Bought interests in the Barnett Shale play.NA Nova Energy Rife Energy Operating Inc. 3 Bought interests in the Barnett Shale.NA Pilgrim Petroleum Undisclosed 3 Bought acreage in Clay County, Texas.NA Pogo Producing Undisclosed 2 Bought 46,000 acres in the Bakken Shale play in North

Dakota.NA Quest Oil Corp. Gaither Petroleum 1 Bought interests in Barnett Shale acreage.NA Richey Ray Management Lexington Resources 2 Bought interests in the Barnett Shale.NA Storm Cat Energy Undisclosed 1 Bought acreage in the Fayetteville Shale play.NA TBX Resources Undisclosed 2 Bought Barnett Shale interests.NA Unicorp Inc. La Mesa Partners 1 Bought 2,500 acres in the New Albany play.NA Universal Property L&R Energy Corp. 2 Bought Barnett Shale interests.NA US Energy Holdings Taylor Exploration 1 Bought acreage in Crockett County, Texas.NA Westside Energy Undisclosed 3 Bought interests in Barnett Shale acreage.NA Wynn-Crosby Energy Inc. Undisclosed 1 Bought 2,600 acres in the Barnett Shale.NA XTO Energy Inc. Undisclosed 2 Bought 166,000 undeveloped acres in the Barnett Shale.

Source: Natexis Bleichroeder Inc., John S. Herold Inc.

W E E X P E C T M O R E

D Y N A M I CIn an ever-changing world, the critical variables of our business, from commodity

prices to future growth plans, are constantly in motion. At XTO, our leadership

provides the dynamic decision-making to meet the dynamic challenges. It’s a

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Documents

Investors Guide Shale Gas 2007